In oil and gas exploration it is always desirable to understand the structure and properties of the geological formation surrounding a borehole, in order to determine if the formation contains hydrocarbon resources (oil and/or gas), to estimate the amount and producibility of hydrocarbon contained in the formation, and to evaluate the best options for completing the well in production. A significant aid in this evaluation is the use of wireline logging and/or logging-while-drilling (LWD) measurements of the formation surrounding the borehole (referred to collectively as "logs" or "log measurements"). Typically, one or more logging tools are lowered into the borehole and the tool readings or measurement logs are recorded as the tools traverse the borehole. These measurement logs are used to infer the desired formation properties.
In evaluating the hydrocarbon production potential of a subsurface formation, the formation is described in terms of a set of "petrophysical properties." Such properties may include: (1) the lithology or the rock type, e.g., amount of sand, shale, limestone, or more detailed mineralogical description, (2) the porosity or fraction of the rock that is void or pore space, (3) the fluid saturations or fractions of the pore space occupied by oil, water and gas, and others. Wireline logging tools do not directly measure petrophysical properties, they measure "log properties", for example, bulk density, electrical resistivity, acoustic velocity, or nuclear magnetic resonance (NMR) decay. Log properties are related to petrophysical properties via a set of mathematical or statistical relations, which are generally known in the art. In practice, frequently several different logging tools are combined and used simultaneously to obtain an integrated set of measurements. Thus, different tools may be used to obtain information about the same set of formation properties using different techniques, or different tools may be used to obtain information about different formation properties. Due to differences in physical measurement mechanisms and other factors, different logging tools have different volumes or zones of investigation, hence different measurement resolutions.
Subsurface formations are generally heterogeneous, so that porosity, saturation and lithology vary with position. A common example of heterogeneity is the presence in the formation of geological layers, or beds. Because logging tools have a nonzero volume of investigation, more than one layer may lie within the volume of investigation of a tool. In such cases, the petrophysical evaluation of one layer may be distorted by the presence of another layer falling within the larger volume of investigation of the tool.
The above phenomenon leads to a specific problem in the analysis of subsurface formations that include one or more underground layers, especially when the layers are thin compared with the vertical resolution of the measuring tool. Relatively thin layers (for example, less than about one foot) frequently come in groups of sometimes hundreds of layers, and have become subject to significant commercial interest because of their production potential. Any knowledge about the composition and properties of such layered formations that helps better estimate their production potential has thus become increasingly valuable.
As noted above, however, many of the standard wireline and LWD logs record data with a resolution along the borehole (generally this is the vertical resolution) - that is coarser than the geological layering of the formation. The effect of having low-resolution logs is that an interpretation of the data tends to be an average description of the formation that can seriously mislead the users of the interpretation. This "averaging" presents a particular problem in formations that contain a small fraction of thin, highly permeable and porous sand layers incorporated within a formation that consists predominantly of low permeability silts or essentially impermeable shales. In such formations the log properties that would reveal the sand layers are dominated, and thus masked, by the opposite log properties of the silts and shales. Accordingly, the averaging which is due to the low resolution of the measuring tool leads to underestimating of the production potential of the formation.
For example, many of the low resistivity and low contrast pay sands are known to be thinly laminated sand/silt or shale sequences. Most commercially available resistivity logging tools have coarse vertical resolution and fail to read resistivity of individual sand or shale layers. Instead, they read only the averaged horizontal resistivity that is low and dominated by the high conductivity of silt and shale layers, although individual sand layers can be highly resistive. As a result, the low resistivity of the layer sequence may be incorrectly interpreted as poor hydrocarbon potential of the formation.
Similar difficulty exists for NMR logging in thinly laminated formations. NMR logging tools have proved very useful in formation evaluation. Tools of this type include, for example, the centralized MRIL.RTM. tool made by NUMAR Corporation, a Halliburton company, and the sidewall CMR tool made by Schlumberger. The MRIL.RTM. tool is described, for example, in U.S. Pat. 4,710,713 to Taicher et al. and in various other publications including: "Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination," by Miller, Paltiel, Gillen, Granot and Bouton, SPE 20561, 65th Annual Technical Conference of the SPE, New Orleans, La., Sept. 23-26, 1990; "Improved Log Quality With a Dual-Frequency Pulsed NMR Tool," by Chandler, Drack, Miller and Prammer, SPE 28365, 69th Annual Technical Conference of the SPE, New Orleans, La., Sept. 25-28, 1994. Certain details of the structure and the use of the MRIL.RTM. tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200; 5,696,448 and 5,936,405. The structure and operation of the Schlumberger CMR tool is described, for example, in U.S. Pat. Nos. 4,939,648; 5,055,787 and 5,055,788 and further in "Novel NMR Apparatus for Investigating an External Sample," by Kleinberg, Sezginer and Griffin, J. Magn. Reson. 97, 466-485, 1992. The content of the above patents is hereby expressly incorporated by reference for all purposes, and all non-patent references are incorporated by reference for background.
Generally, although the NMR tools respond only to a very limited zone in the radial direction, their vertical resolution is not sharp enough to identify individual layers. The vertical resolution of the tools gets worse when NMR echo-trains are stacked over multiple events to improve the signal-to-noise ratio (SNR). Consequently, the echo-trains obtained from NMR logging reflect the average properties of the laminated sequences, so that the properties of non-productive silt or shale layers may mask those of productive sand layers.
One way to address the issue of layering identification is by visual inspection of cores, which inspection can identify the boundaries for different layers. Further, there are several logging tools that are capable of identifying the geological layering and classifying the various layer types. These are imaging tools, such as the Borehole Televiewer (BHTV), CAST, the Electric Micro Imaging (EMI) Tool, the Formation Micro Scanning (FMS) Tool, and others. Similarly, other fine resolution tools such as a dipmeter, high resolution Pe log, and high frequency dielectric log HFDT, may also be used to provide high-resolution layering information, when laminae are thicker than a few inches. It has been determined that the EMI tool, for example, is capable of identifying the geological layering and also, with some care, of classifying the various layer types.
Having available geological information from high vertical resolution logs, it is desirable to estimate sand properties out of the averaged measurements. In the case of echo-train data from a NMR logging tool, it is desirable to determine the echo-trains specific to particular lithological types, which can then be used to estimate the lithology-specific T.sub.2 -distribution for the formation layers. Using well-known mathematical transformations one can then obtain much more accurate permeability estimates for each lithology type, and thus obtain a realistic evaluation of the producibility potential of the formation. Such high-resolution estimates are very desirable, because otherwise the producibility potential of certain laminated formations, which may appear to have low permeability, may be overlooked.